It is generally known that oils from underground reservoirs can be recovered by the injection of fluids which displace such oils. The recovery (displacing) fluid is injected into the reservoirs through one or more injection wells, and the oil is recovered either through separate production wells or through production zones in the injection well which are virtually separated from the injection zones.
Generally, the fluids which are used to displace oils can be divided into three catagories, namely, immiscible, directly miscible and conditionally miscible fluids.
Immiscible displacing fluids, such as water or dry gas are those which form a separate phase from the oils in the formation at the temperatures and pressures encountered there. Such fluids are usually relatively ineffective in recovering oils. They displace a portion of the oil from the zone (known as the "pay zone") in the formation where the oil accumulates, but the portion displaced is usually relatively small, because much of the oil is left in the pores of the reservoir rock by the interfacial forces that exist between the immiscible fluids.
Directly miscible displacing agents (for example, liquified petroleum gases, called "LPG" and consisting primarily of propane and butane) are recovery agents which, at the temperatures and pressures of the pay zones are present as a single phase with the oil and therefore are completely miscible on first contact. Since interfacial forces are absent, such agents are more efficient than immiscible displacing agents in recovering reservoir oil, providing that fingering does not result in early breakthrough of solvent.
A third class of agents, namely conditionally miscible fluids, is also known. Examples of such recovery agents are enriched natural gas, gas plant or refinery ends, flue gas or their mixtures, carbon dioxide, and at high pressure, nitrogen, methane or natural gas. Such recovery agents are not miscible on first contact with the reservoir oils at the temperatures and pressures normally found in the reservoir, but can become miscible or nearly miscible during injection at high pressures and by an interchange of components with the reservoir oil. This process gives recoveries higher than the immiscible process but not as high as the directly miscible process.
Because of the higher recoveries obtainable with directly miscible recovery agents as opposed to conditionally miscible or immiscible ones, it would naturally be preferable to use directly miscible recovery agents on a continuous injection basis. However, all the directly miscible recovery agents are more expensive and contain more energy per reservoir barrel than the immiscible or conditionally miscible agents, so it would be costly to inject large quantities. Some of the expense can be reduced by injecting only a small bank of the directly miscible recovery fluid and by "chasing" the miscible fluid from the formation with cheaper displacing agents, such as methane, carbon dioxide or natural gas, nitrogen, or their mixtures. However, such chasing operations have a significant cost in themselves and become inefficient in cases where the growth of long finger-like projections of solvent known as "fingering" can cause the chase gas to directly contact the oil, resulting in an inefficient immiscible displacement of oil.
U.S. Pat. No. 2,867,277 of Weinaug teaches the injection of a mixture of petroleum and a hydrocarbon displacing material followed by injection of the displacing material alone. The purpose of the injection of the mixture is to form a transition zone between the petroleum and the hydrocarbon displacing material. Preferably, displacing materials are used in sequence. A transition zone is formed between each displacing material and the one which follows it, by injecting a mixture of the two fluids.
The use of a mixture of fluids which is close in viscosity to the reservoir oil is very expensive in today's economic climate, as such mixtures involve fluids of high economic value. Accordingly, the Weinaug process is too expensive for use.
Accordingly, it is an object of the invention to provide a way of creating initial miscibility of a conditionally miscible recovery agent without the use of large amounts of expensive recovery agents and without the use of extremely high pressures and to avoid or minimize and rectify the problem of fingering.
According to the invention, the injection process is started by introducing into the well a small slug of a fluid (hereinafter called "adapting fluid") which is fully miscible with the reservoir oil, and which is miscible with the conditionally miscible recovery agent (which will usually be a gas), over a wide range of concentrations (e.g., from about 20% adapting fluid-80% gas to 80% adapting fluid-20% gas). The adapting fluid should be a fluid which is directly miscible with the reservoir oil on a first contact basis at the temperatures and pressures to be used, and which is miscible over a wide range of concentrations (from about 80-20%) with a conditionally miscible fluid to be used. Although such miscible fluids include relatively expensive recovery agents, natural gas liquids (NGL), liquid petroleum gas (LPG), and hexane, heptane and higher hydrocarbon fractions, as well as acetone and lower alcohols, these can have appreciable concentrations of C.sub.1, or C.sub.2 hydrocarbon added to reduce cost, provided miscibility is maintained.
A particularly preferred adapting fluid is a stream of plant gas or refinery by-products including sufficient hydrocarbons of C.sub.2 and greater chain lengths, so as to be miscible with the reservoir oil. Such streams of gas plant or refinery by-products can also include significant mole fractions of C.sub.1 hydrocarbon, nitrogen, sulphur dioxide and hydrogen sulphide, provided there are enough hydrocarbons present to ensure miscibility with the reservoir oil on a first contact basis.
The adapting fluid is followed by several slugs, in which the concentrations of adapting fluid are descreased and increasing concentrations are included of a fluid miscible with the adapting fluid, but which is only conditionally miscible with the reservoir oils. Such fluids are sometimes also known as multiple contact miscible fluids. Preferred conditionally miscible fluids are enriched natural gas, gas plant or refinery light ends, carbon dioxide and nitrogen, natural gas, ethane and/or their mixtures. It is particularly preferred to use off-gas from oil refining, which is frequently available at very low cost in oil producing regions. Such off-gas may typically have methane as its largest single component, small amounts of C.sub.2 -C.sub.4 hydrocarbons, and some nitrogen, sulphur dioxide and hydrogen sulphide. Another multiple contact miscible fluid can be flue gas from different kinds of plants and would contain nitrogen, nitrogen, oxides and carbon dioxide. Still another multiple contact miscible fluid can be pure carbon dioxide or a gas consisting mostly of carbon dioxide. Other suitable fluids will be obvious to one skilled in the art.
The slug of adapting fluid injected need not be large enough to have any significant effect at driving oil from the reservoir towards a production well, and can be as small as 500 m.sup.3 at reservoir conditions. If injection takes place through several wells, the slug injected at each well should be at least 500 m.sup.3 at reservoir conditions. There is no fixed upper limit to the size of the slug of adapting fluid, but the adapting fluid is generally more expensive than the conditionally miscible recovery fluid so that slugs of over 15% of the pore volume at the reservoir conditions are not usually used. Generally, the total volume of all slugs used, at the reservoir conditions, will not exceed 35% to 40% of the hydrocarbon pore volume of the reservoir.
The viscosity of the first slug of adapting fluid need not be similar to that of the oil in the reservoir, and likewise the viscosity of each slug need not be similar to that of the slug before it. However, the optimum period of shut-in becomes longer when the viscosity difference between slugs or between the first slug and the reservoir oil is greater.
Following injection of the slug, the well is shut-in for a period of at least two days, and preferably of about two weeks or longer, depending on the reservoir characteristics and the nature of the fluids. "Shut-in" as used in this disclosure is a period of time in which no injection of fluid is passed into the injector well or wells. However, it can include a "pulsed" shut-in, where short periods of injection interrupt the shut-in period, or where shut-in of one injection well is alternated with shut-in of another injection well. A pulsed shut-in of this sort may of certain cases aid mixing of the injected fluid with the fluids already in the well. During the period of shut-in, the fluid exchanges components with the reservoir oil, forming a mixing zone in the volume of the reservoir immediately surrounding the perforated level of the well. After the period of shut-in, a second slug, of mixed adapting fluid and the conditionally miscible recovery fluid, is introduced into the well followed by a period of shut-in. Suitably the second slug is formed from 80-50% adapting fluid and 50-20% conditionally miscible recovery fluid totalling 100%. This slug, which again may be as small as 500 m.sup.3 at reservoir conditions, is followed by a further period of shut-in of at least two days. A third slug, having a lesser percentage of adapting fluid and greater percentage of conditionally miscible recovery fluid than the second slug is injected after the period of shut-in. Suitably the third slug may have 60-30% adapting fluid and 70-40% conditionally miscible fluid, totalling 100%, provided the percentages chosen are such that the percentage of adapting fluid is less than that in the previous slug, and the percentage of conditionally miscible recovery fluid is greater than that in the preceding slug. Each slug has a volume of 500 m.sup.3 at the reservoir conditions. A fourth slug may also be injected into the well if desired after the period of shut-in. This slug will have a larger percentage of conditionally miscible fluid and a smaller percentage of adapting fluid than the third slug, i.e., from 40-20% adapting fluid and 60-80% conditionally miscible fluid. Again it is followed by a period of at least two days of shut-in. Generally, the use of any slug which is over 10% to 15% of the hydrocarbon pore volume at the reservoir conditions is not preferred, because of the cost of the adapting fluid.
After the shut-in period following injection of the last slug, injection of the conditionally miscible fluid is started. The oil is recovered, either from a production well separate from the injection well, or from a zone which is vertically separated from the injection zone on the well used for injection.
When the compositions of the fluids are designed correctly, then the conditionally miscible fluid injected into the well will be completely miscible with the slug immediately adjacent to the perforated zone of the well. Thus, there is a transition zone formed by the slugs of gradually increasing concentration of conditionally miscible fluid extending from the reservoir oil to the last slug injected.
The periods of shut-in are essential to this process as they give time for a transition zone to establish itself between each slug and the slug (or reservoir oil) which it contacts as it spreads away from the well and prevents the growth of fingers. The periods of shut-in needs not be very long, provided they are sufficiently long for an adequate transition zone to form.
It has been found that periods of about two weeks will work well. Depending on the size of the slug and the properties of the reservoir rock and fluids, much longer periods of shut-in may be detrimental, as the slug could be consumed in time by diffusion into the surrounding oil and gas zones. Obviously it is uneconomical in most circumstances to have an unduly long period of shut-in, because it is usually desirable to begin recovery from the field as soon as possible. Therefore, a cumulative shut-in period of more than approximately four months between the first slug and the conditionally miscible fluid is not preferred. The delays by shut-in times can be offset by higher initial injection rates during the solvent bank placement so that the average voidage replacement is kept at some planned level.
The production wells may be shut-in or may continue to produce during the shut-in period of the injection wells, subject to the constraint that the pressure at the displacement front is maintained above the minimum miscibility pressure. This may be insured by injecting the solvent at injected rates above those required for voidage displacement before shut-in.
In preferred embodiments, only a limited volume of the conditionally miscible fluid will be used and a change will be made of injection of a cheaper chase fluid such as natural gas, flue gas or nitrogen or their mixtures. When such preferred embodiments are used, slugs of mixtures of the conditionally miscible fluid and the chase fluid will be injected, with shut-in periods between slugs to aid in the maintenance of a uniform displacement front.
In order to facilitate the spreading of the injected solvent throughout the oil zone and also to decrease the time that it takes to inject the solvent, it is usually desirable to use a maximum number of wells for solvent injection purposes. A suitable way to do this is to utilize all available wells for solvent injection purposes, whether they are injectors, producers or observation wells in normal operations and irrespective of whether they are drilled vertically or horizontally. If a well is normally used as a producer, it can be recompleted dually; or by using the appropriate equipment so that the upper part of the oil zone is used for solvent injection, while the well could be continue to produce from the lower part of the oil zone or the converse.
Once placement of the solvent has been achieved in the designed manner, the wells can be converted into conventional producers, injectors or observation wells. The use of the maximum number of wells whether drilled vertically or horizontally for solvent injection is especially important in vertical miscible displacement processes.